In many applications, an oil or gas well is drilled with a fluid driven motor, also referred to as a mud motor. The mud motor is affixed to the lower end of a drill pipe or drill string. Drilling fluid, or mud, is pumped down through the drill pipe that forms the drill string by pumps situated at the surface of a drill site. The drilling fluid is pumped downhole through the drill pipe under pressure and passes through the mud motor, turning a rotor within the mud motor. For a given mud motor, there is an optimum, a minimum, and a maximum mud flow rate. The rotor turns a drive shaft that turns a drill bit to drill through the downhole formations. Similarly, a milling tool can be affixed to the mud motor instead of a drill bit for milling metal items that may be found downhole. After passing through the mud motor, the drilling fluid typically passes on through the drill bit or milling tool. After exiting the drill bit or milling tool, the drilling fluid passes back up the well bore in an annular space around the drill string.
As the drill bit turns and drills through the formation, it grinds, tears, or gouges pieces of the formation loose. These pieces of the formation, called cuttings, can vary in size from powdery particles to large chunks, depending upon the type of formation, the type of drill bit, the weight on the drill bit, and the speed of rotation of the drill bit. Similarly, as a milling tool turns, it removes cuttings from the metal item being milled away or milled through. As the drilling fluid exits the drill bit or milling tool, it entrains the cuttings and carries them up the annulus of the well bore to the surface of the well site. At the surface, the cuttings are removed from the drilling fluid, which may then be recycled downhole.
Depending upon the type of formation, the drilling depth, and many other factors, the drilling fluid used at any given time is designed to satisfy various requirements relative to the well drilling operation. One of the functions of the drilling fluid is to keep the cuttings in suspension and to carry them to the surface of the well site for disposal. If the cuttings are not efficiently removed from the well bore, the drill bit or milling tool can become clogged, limiting its effectiveness. Similarly, the well bore annulus can become clogged, preventing further circulation of drilling fluid, or even causing the drill pipe to become stuck. Therefore, the cuttings must flow with the drilling fluid up the annulus to the surface. Various features of the drilling fluid are chosen so that removal of the cuttings will be insured. The two main features selected to insure cutting removal are drilling fluid viscosity and flow rate.
Adequate viscosity can be insured by proper formulation of the drilling fluid. Adequate flow rate is insured by operating the pumps at a sufficiently high speed to circulate drilling fluid through the well at the required volumetric velocity and linear velocity to maintain cuttings in suspension. In some circumstances, the mud flow rate required for cutting removal is higher than the maximum desired mud flow rate through the mud motor. This can be especially true when the mud motor moves into an enlarged bore hole, where the annulus is significantly enlarged. If the maximum desired flow rate for the mud motor is exceeded, the mud motor can be damaged. On the other hand, if the mud flow rate falls below the minimum flow rate for the mud motor, drilling is inefficient, and the motor may stall.
In cases where keeping the cuttings in suspension in the bore hole annulus requires a mud flow rate greater than the maximum allowed mud flow rate through the motor, there may be a means for diverting some of the mud flow from the bore of the drill string to the annulus, generally at a point near, but just above, the mud motor. This will prevent exceeding the maximum mud flow rate for the mud motor, while providing an adequate flow rate in the annulus to keep the cuttings in suspension.
Some tools are known for this and similar purposes. Some of the known tools require the pumping of a ball downhole to block a passage in the mud flow path, usually resulting in the shifting of some flow control device downhole to divert drilling fluid to the annulus. Such tools usually suffer from the disadvantage of not being returnable to full flow through the mud motor in the event that reduced mud flow becomes possible thereafter. Other such tools might employ a fracture disk or other release means with these release means suffering from the same disadvantage of not being reversible. At least one known tool uses mud pump cycling to move a sleeve up and down through a continuous J-slot to reach a portion of the J-slot, which will allow increased longitudinal movement of the sleeve, ultimately resulting in the opening of a bypass outlet to the annulus. This tool suffers from the disadvantage that the operator must have a way of knowing exactly the position of the J-slot pin to initiate bypass flow at the appropriate time. Initiating increased flow when bypass has not been established can damage the mud motor; while operating at low flow when bypass has been established will lead to poor performance or stalling.
Therefore, a need exists for a tool that will reliably bypass a portion of the drilling fluid to the annulus when a predetermined flow rate is exceeded and that will close the bypass path when the flow rate falls back below a predetermined level. This will allow the operator to have complete control of the bypass flow by operation of the drilling fluid pumps at selected levels. It is to such a tool that the inventive concepts disclosed herein are directed.